U.S. patent application number 15/722996 was filed with the patent office on 2018-04-05 for system for using pressure exchanger in mud pumping application.
The applicant listed for this patent is Energy Recovery, Inc.. Invention is credited to David Deloyd Anderson, Joel Gay, Farshad Ghasripoor, Adam Rothschild Hoffman, Jeremy Grant Martin.
Application Number | 20180094648 15/722996 |
Document ID | / |
Family ID | 61757956 |
Filed Date | 2018-04-05 |
United States Patent
Application |
20180094648 |
Kind Code |
A1 |
Hoffman; Adam Rothschild ;
et al. |
April 5, 2018 |
SYSTEM FOR USING PRESSURE EXCHANGER IN MUD PUMPING APPLICATION
Abstract
A system includes a pump configured to pressurize a first fluid,
and a pressure exchanger (PX). The PX is configured to receive a
second fluid, to receive the pressurized first fluid, and to
utilize the pressurized first fluid to pressurize the drilling mud
for transport to a well.
Inventors: |
Hoffman; Adam Rothschild;
(San Francisco, CA) ; Gay; Joel; (San Ramon,
CA) ; Ghasripoor; Farshad; (Berkeley, CA) ;
Anderson; David Deloyd; (Castro Valley, CA) ; Martin;
Jeremy Grant; (Oakland, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Energy Recovery, Inc. |
San Leandro |
CA |
US |
|
|
Family ID: |
61757956 |
Appl. No.: |
15/722996 |
Filed: |
October 2, 2017 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62403488 |
Oct 3, 2016 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
B01D 21/283 20130101;
F04F 13/00 20130101; E21B 21/01 20130101; E21B 21/06 20130101; E21B
21/067 20130101; B01D 21/262 20130101; E21B 43/34 20130101; B01D
19/00 20130101; E21B 21/08 20130101; E21B 21/065 20130101 |
International
Class: |
F04F 13/00 20060101
F04F013/00; E21B 21/08 20060101 E21B021/08; B01D 21/28 20060101
B01D021/28; B01D 19/00 20060101 B01D019/00; B01D 21/26 20060101
B01D021/26 |
Claims
1. A system, comprising: a pump configured to pressurize a first
fluid; and a pressure exchanger (PX) configured to receive a second
fluid, to receive the pressurized first fluid, and to utilize the
pressurized first fluid to pressurize the second fluid for
transport to a well.
2. The system of claim 1, comprising: a fluid tank configured to
store the first fluid upstream of the pump; and a mud pit
configured to store the second fluid to be supplied to the PX.
3. The system of claim 2, comprising a cleaning system configured
to clean the second fluid and deposit the clean second fluid in the
mud pit.
4. The system of claim 3, wherein the cleaning system comprises a
shale shaker, a degasser, a desander, a desilter, a centrifuge, or
a combination thereof.
5. The system of claim 2, wherein the cleaning system comprises a
mixer and hopper configured to stir the second fluid in the mud
pit.
6. The system of claim 5, comprising a separator configured to
remove particulates from the first fluid output by the PX.
7. The system of claim 6, wherein the separator is configured to
output the removed particulates to the cleaning system.
8. The system of claim 7, wherein the cleaning system comprises a
centrifuge configured to remove the first fluid from the second
fluid and to output the first fluid to the fluid tank.
9. The system of claim 1, wherein a first flow rate of the
pressurized first fluid into the PX is substantially equal to a
second flow rate of the second fluid into the PX.
10. The system of claim 1, wherein a first flow rate of the
pressurized first fluid into the PX is greater than a second flow
rate of the second fluid into the PX.
11. The system of claim 10, wherein the first flow rate of the
pressurized first fluid into the PX is approximately 120% of the
second flow rate of the second fluid into the PX.
12. A pressure exchanger (PX), comprising: a low pressure inlet
configured to receive a used first fluid from a drilling
application; a high pressure inlet configured to receive a second
fluid; a low pressure outlet configured to output the second fluid;
and a high pressure outlet configured to output the first fluid for
transport to a well; wherein the PX is configured to utilize the
second fluid to pressurize the first fluid.
13. The PX of claim 12, comprising: first and second end structures
at respective first and second ends of the PX; a rotor disposed
between the first and second end structures; and a housing disposed
about the rotor.
14. The PX of claim 13, wherein the rotor comprises a plurality of
channels extending longitudinally through the rotor.
15. The PX of claim 14, wherein the first and second end structures
each comprise a manifold and an end plate disposed within the
manifold, wherein the end plate is in fluid communication with the
plurality of channels.
16. A method, comprising: receiving a used first fluid from a
drilling application via a low pressure inlet of a pressure
exchanger (PX); receiving a second fluid via a high pressure inlet
of the PX; utilizing the second fluid to pressurize the used first
fluid within the PX; outputting the used first fluid for transport
to a well; and outputting the second fluid via a low pressure
outlet of the PX.
17. The method of claim 16, comprising pressurizing the second
fluid via a pump.
18. The method of claim 16, comprising: cleaning the used first
fluid; and depositing the clean used first fluid in a mud pit.
19. The method of claim 17, comprising supplying the clean used
first fluid from the mud pit to the low pressure inlet of the
PX.
20. The method of claim 16, comprising depositing the second fluid
into a fluid tank.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application claims priority to and benefit of U.S.
Patent Application No. 62/403,488, entitled "SYSTEM FOR USING
PRESSURE EXCHANGER IN MUD PUMPING APPLICATION", filed Oct. 3, 2016,
which is herein incorporated by reference in its entirety.
BACKGROUND
[0002] This section is intended to introduce the reader to various
aspects of art that may be related to various aspects of the
present disclosure, which are described and/or claimed below. This
discussion is believed to be helpful in providing the reader with
background information to facilitate a better understanding of the
various aspects of the present disclosure. Accordingly, it should
be understood that these statements are to be read in this light,
and not as admissions of prior art.
[0003] The subject matter disclosed herein relates to fluid
handling, and, more particularly, to systems and methods for
pressurizing and pumping drilling fluids ("drilling mud") to a
drilling rig to be sent down a drill string.
[0004] Drilling mud is used in oil and gas drilling applications to
provide hydraulic power, cooling, well control (e.g., using the
weight and pressure of the mud to control the well, which may
encounter pressurized fluids in the formation), to cool the
drilling head and to carry cuttings away from the cutting head. In
drilling applications, drilling mud is typically pressurized (e.g.,
5,000 to 7,500 PSI or more) and pumped using a mud pump to a
drilling rig and down the drilling pipe to a cutting head via a
drill string. The used drilling mud and the cuttings then flow back
up through an annulus between the drilling pipe and a casing.
However, in some embodiments, the drilling mud flow down through
the annulus between the drilling pipe and the casing and then up
the drilling pipe to the rig.
[0005] Drilling mud may include cuttings, clay, various minerals,
aggressive chemicals, salts, and miscellaneous other components
that may place stress on the mud pump, and in some cases shorten
the lifespan of the mud pump. Accordingly, when selecting a mud
pump, durability may be a driving factor.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] Various features, aspects, and advantages of the present
disclosure will become better understood when the following
detailed description is read with reference to the accompanying
figures in which like characters represent like parts throughout
the figures, wherein:
[0007] FIG. 1 is a schematic view of an embodiment of a drilling
application;
[0008] FIG. 2 is an exploded perspective view of an embodiment of a
pressure exchanger (PX);
[0009] FIG. 3 is an exploded perspective view of an embodiment of a
PX in a first operating position;
[0010] FIG. 4 is an exploded perspective view of an embodiment of a
PX in a second operating position;
[0011] FIG. 5 is an exploded perspective view of an embodiment of a
PX in a third operating position;
[0012] FIG. 6 is an exploded perspective view of an embodiment of a
PX in a fourth operating position;
[0013] FIG. 7 is a schematic of an embodiment of the drilling
application of FIG. 1;
[0014] FIG. 8 is a schematic of an embodiment of the drilling
application in which particulates from the separator are added to
the mud loop, and water removed by the centrifuge is added to the
water loop;
[0015] FIG. 9 is a schematic illustrating flow rates in an
embodiment of the drilling application with balanced flow;
[0016] FIG. 10 is a schematic illustrating flow rates in an
embodiment of the drilling application with 20% lead flow; and
[0017] FIG. 11 is a flow chart of a process for pressurizing
drilling mud.
DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS
[0018] One or more specific embodiments of the present disclosure
will be described below. These described embodiments are only
exemplary of the present disclosure. Additionally, in an effort to
provide a concise description of these exemplary embodiments, all
features of an actual implementation may not be described in the
specification. It should be appreciated that in the development of
any such actual implementation, as in any engineering or design
project, numerous implementation-specific decisions must be made to
achieve the developers' specific goals, such as compliance with
system-related and business-related constraints, which may vary
from one implementation to another. Moreover, it should be
appreciated that such a development effort might be complex and
time consuming, but would nevertheless be a routine undertaking of
design, fabrication, and manufacture for those of ordinary skill
having the benefit of this disclosure.
[0019] When introducing elements of various embodiments of the
present disclosure, the articles "a," "an," "the," and "said" are
intended to mean that there are one or more of the elements. The
terms "comprising," "including," and "having" are intended to be
inclusive and mean that there may be additional elements other than
the listed elements.
[0020] In many drilling applications drilling mud is pressurized
and pumped down the drill string to the cutting head to provide
hydraulic power, cooling, well control (e.g., using the weight and
pressure of the mud to control the well, which may encounter
pressurized fluids in the formation), and displacement of the
cuttings. The used drilling mud travels back up to the surface
through an annulus between the drill string and a casing. The used
drilling mud may then be cleaned and reused. Drilling mud may
include cuttings, clay, various minerals, aggressive chemicals,
salts, and miscellaneous other components that may place stress on
the mud pump, which may shorten the lifespan of the mud pump.
[0021] As discussed in detail below, by pressurizing a clean fluid
(e.g., water) with a pump and then using a hydraulic energy
transfer system, such as a pressure exchanger (PX), to transfer
work and/or pressure from the high pressure clean fluid to the
drilling mud allows the drilling mud to be pumped and pressurized
without running the drilling mud through the pump. In some
embodiments, the hydraulic energy transfer system may be a rotating
isobaric pressure exchanger that transfers pressure between a high
pressure fluid (e.g., high pressure energizing clean fluid, such as
pressurized water) and a low pressure fluid (e.g., drilling mud).
The utilization of the PX eliminates the need to run the drilling
mud through a mud pump, which may stress or damage the pump more
than water. The PX is compact, durable, easy to maintain, and can
easily be deployed with redundancy.
[0022] The PX may include one or more chambers (e.g., 1 to 100) to
facilitate pressure transfer and equalization of pressures between
volumes of first and second fluids. In some embodiments, the
pressures of the volumes of first and second fluids may not
completely equalize. Thus, in certain embodiments, the PX may
operate isobarically, or the PX may operate substantially
isobarically (e.g., wherein the pressures equalize within
approximately +/-1, 2, 3, 4, 5, 6, 7, 8, 9, or 10 percent of each
other). In certain embodiments, a first pressure of a first fluid
(e.g., a high pressure energized clean fluid) may be greater than a
second pressure of a second fluid (e.g., drilling mud). For
example, the first pressure may be between approximately 5,000 kPa
to 25,000 kPa, 20,000 kPa to 50,000 kPa, 40,000 kPa to 75,000 kPa,
75,000 kPa to 100,000 kPa or greater than the second pressure.
Thus, the PX may be used to transfer pressure from a first fluid
(e.g., high pressure energized clean fluid) at a higher pressure to
a second fluid (e.g., drilling mud) at a lower pressure.
[0023] FIG. 1 is a schematic view of an embodiment of a drilling
application 2. As illustrated, a drill string 4 extends through a
casing 6 below a surface 8 of the earth, where a cutting head 10
drills into the earth. Drilling fluids ("drilling mud") are
typically pressurized (e.g., 5,000 to 7,500 psi or more) and pumped
down the drill string 4 to the cutting head 10 to provide hydraulic
power, cooling, well control (e.g., using the weight and pressure
of the mud to control the well, which may encounter pressurized
fluids in the formation), and displacement of the cuttings. The
drilling mud is then pumped up, away from the cutting head 10, and
through the annulus between the drill string 4 and the casing 6.
The used mud carries the cuttings away from the cutting head 10. In
typical riser drilling applications, the used mud is pumped up
through the annulus between the drill string and and the casing
back up to the surface 8. The used drilling mud may go through one
or more cleaning systems 12 or processes (e.g., shale shaker,
degasser, desander, desilter, centrifuge, etc.) and then be
deposited in a mud pit 14.
[0024] Typically, drilling mud from the mud pit 14 is pressurized
and pumped using a mud pump. However, clay, salt, and minerals in
the drilling mud may put stress on a mud pump that may shorten its
lifespan. In the illustrated embodiment, a PX 16 is used to
pressurize and pump the drilling mud. Specifically, clean fluid
(e.g., water) from a clean fluid supply 18 (e.g., a water tank) is
pressurized (e.g., 5,000 to 7,500 psi or more) using a pump 20 and
supplied to the high pressure (HP) inlet 22. The pump may be a
triplex plunger pump with a discharge pulsation damper, or some
other pump suitable for pumping clean fluids. Drilling mud from the
mud pit 14 is supplied to the low pressure (LP) inlet. The PX 16
transfers pressure from the high pressure clean fluid to the low
pressure drilling mud, outputting low pressure clean fluid through
the LP outlet 26, and high pressure drilling mud through the HP
outlet 28. Though FIG. 1 shows a single PX 16, it should be
understood that a drilling application 2 may include multiple PXs
16, coupled to one another by plumbing or manifolds, which may have
valves for switching PXs 16 online and offline. The clean fluid
from the LP outlet 26 is deposited in the water tank 18. The
drilling mud from the HP outlet 28 travels to and down the drill
string 4.
[0025] Thus, the drilling application may include a drilling mud
loop 30 and a clean fluid loop 32, which may only interact with one
another, if at all, in the PX 16. The PX 16 has fewer moving parts
and is generally better suited to processing drilling mud than the
pump 20. Thus, because the pump 20 is pumping clean fluid (e.g.,
water) rather than drilling mud, the pump 20 undergoes less stress
than a comparable pump in an embodiment in which the pump pumps
drilling mud. In some embodiments, the pump 20 handling clean fluid
rather than drilling mud may alter the pump 20 used in the system
2. For example, because the pump 20 processes water, rather than
drilling mud, a pump that is less durable, but offers better
performance or efficiency may be selected instead. Similarly, in
some applications, the mud cleaning system 12 may be less thorough
because the mud no longer needs to be clean enough to be processed
by the pump 20.
[0026] FIG. 2 is an exploded view of an embodiment of a rotary PX
16 that may be utilized in place of a mud pump in a drilling
application, as described in detail below. As used herein, the PX
16 may be generally defined as a device that transfers fluid
pressure between a high-pressure inlet stream and a low-pressure
inlet stream at efficiencies in excess of approximately 50%, 60%,
70%, or 80% without utilizing centrifugal technology. In this
context, high pressure refers to pressures greater than the low
pressure. The low-pressure inlet stream of the PX 16 may be
pressurized and exit the PX 16 at high pressure (e.g., at a
pressure greater than that of the low-pressure inlet stream), and
the high-pressure inlet stream may be depressurized and exit the PX
16 at low pressure (e.g., at a pressure less than that of the
high-pressure inlet stream). Additionally, the PX 16 may operate
with the high-pressure fluid directly applying a force to
pressurize the low-pressure fluid, with or without a fluid
separator between the fluids. Examples of fluid separators that may
be used with the PX 16 include, but are not limited to, pistons,
bladders, diaphragms and the like. In certain embodiments, isobaric
pressure exchangers may be rotary devices. Rotary isobaric pressure
exchangers (PXs) 16, such as those manufactured by Energy Recovery,
Inc. of San Leandro, Calif., may not have any separate valves,
since the effective valving action is accomplished internal to the
device via the relative motion of a rotor with respect to end
covers, as described in detail below with respect to FIGS. 2-7.
Rotary PXs 16 may be designed to operate with internal pistons to
isolate fluids and transfer pressure with little mixing of the
inlet fluid streams. Reciprocating PXs 16 may include a piston
moving back and forth in a cylinder for transferring pressure
between the fluid streams. Any PX 16 or plurality of PXs 16 may be
used in the disclosed embodiments, such as, but not limited to,
rotary PXs, reciprocating PXs, or any combination thereof. While
the discussion with respect to certain embodiments for measuring
the speed of the rotor may refer to rotary PXs 16, it is understood
that any PX 16 or plurality of PXs 16 may be substituted for the
rotary PX 16 in any of the disclosed embodiments.
[0027] In the illustrated embodiment of FIG. 2, the PX 16 may
include a generally cylindrical body portion 40 that includes a
housing 42 and a rotor 44. The rotary PX 16 may also include two
end structures 46 and 48 that include manifolds 50 and 52,
respectively. Manifold 50 includes inlet and outlet ports 54 and 56
and manifold 52 includes inlet and outlet ports 60 and 58. For
example, inlet port 54 may receive a high-pressure first fluid and
the outlet port 56 may be used to route a low-pressure first fluid
away from the PX 16. Similarly, inlet port 60 may receive a
low-pressure second fluid and the outlet port 58 may be used to
route a high-pressure second fluid away from the PX 16. The end
structures 46 and 48 include generally flat end plates 62 and 64,
respectively, disposed within the manifolds 50 and 52,
respectively, and adapted for liquid sealing contact with the rotor
44. The rotor 44 may be cylindrical and disposed in the housing 42,
and is arranged for rotation about a longitudinal axis 66 of the
rotor 44. The rotor 44 may have a plurality of channels 68
extending substantially longitudinally through the rotor 44 with
openings 70 and 72 at each end arranged symmetrically about the
longitudinal axis 66. The openings 70 and 72 of the rotor 44 are
arranged for hydraulic communication with the end plates 62 and 64,
and inlet and outlet apertures 74 and 76, and 78 and 80, in such a
manner that during rotation they alternately hydraulically expose
liquid at high pressure and liquid at low pressure to the
respective manifolds 50 and 52. The inlet and outlet ports 54, 56,
58, and 60, of the manifolds 50 and 52 form at least one pair of
ports for high-pressure liquid in one end element 46 or 48, and at
least one pair of ports for low-pressure liquid in the opposite end
element, 48 or 46. The end plates 62 and 64, and inlet and outlet
apertures 74 and 76, and 78 and 80 are designed with perpendicular
flow cross sections in the form of arcs or segments of a
circle.
[0028] With respect to the PX 16, an operator has control over the
extent of mixing between the first and second fluids, which may be
used to improve the operability of the PX 16. For example, varying
the proportions of the first and second fluids entering the PX 16
allows the operator to control the amount of fluid mixing within
the PX 16. Three characteristics of the PX 16 that affect mixing
are: the aspect ratio of the rotor channels 68, the short duration
of exposure between the first and second fluids, and the creation
of a liquid barrier (e.g., an interface) between the first and
second fluids within the rotor channels 68. First, the rotor
channels 68 are generally long and narrow, which stabilizes the
flow within the PX 16. In addition, the first and second fluids may
move through the channels 68 in a plug flow regime with very little
axial mixing. Second, in certain embodiments, at a rotor speed of
approximately 1200 RPM, the time of contact between the first and
second fluids may be less than approximately 0.15 seconds, 0.10
seconds, or 0.05 seconds, which again limits mixing of the streams.
Third, a small portion of the rotor channel 68 is used for the
exchange of pressure between the first and second fluids.
Therefore, a volume of fluid remains in the channel 68 as a barrier
between the first and second fluids. All these mechanisms may limit
mixing within the PX 16.
[0029] In addition, because the PX 16 is configured to be exposed
to the first and second fluids, certain components of the PX 16 may
be made from materials compatible with the components of the first
and second fluids. In addition, certain components of the PX 16 may
be configured to be physically compatible with other components of
the fluid handling system. For example, the ports 54, 56, 58, and
60 may comprise flanged connectors to be compatible with other
flanged connectors present in the piping of the fluid handling
system. In other embodiments, the ports 54, 56, 58, and 60 may
comprise threaded or other types of connectors.
[0030] FIGS. 3-6 are exploded views of an embodiment of the rotary
PX 16 illustrating the sequence of positions of a single channel 68
in the rotor 44 as the channel 68 rotates through a complete cycle,
and are useful to an understanding of the rotary PX 16. It is noted
that FIGS. 3-6 are simplifications of the rotary PX 16 showing one
channel 68 and the channel 68 is shown as having a circular
cross-sectional shape. In other embodiments, the rotary PX 16 may
include a plurality of channels 68 (e.g., 2 to 100) with different
cross-sectional shapes. Thus, FIGS. 3-6 are simplifications for
purposes of illustration, and other embodiments of the rotary PX 16
may have configurations different from that shown in FIGS. 4-7. As
described in detail below, the rotary PX 16 facilitates a hydraulic
exchange of pressure between two liquids by putting them in
momentary contact within a rotating chamber. In certain
embodiments, this exchange happens at a high speed that results in
very high efficiency with very little mixing of the liquids.
[0031] In FIG. 3, the channel opening 70 is in hydraulic
communication with aperture 76 in endplate 62 and therefore with
the manifold 50 at a first rotational position of the rotor 44. The
opposite channel opening 72 is in hydraulic communication with the
aperture 80 in endplate 64, and thus, in hydraulic communication
with manifold 52. As discussed below, the rotor 44 rotates in the
clockwise direction indicated by arrow 90. As shown in FIG. 3,
low-pressure second fluid 92 passes through end plate 64 and enters
the channel 68, where it pushes first fluid 94 out of the channel
68 and through end plate 62, thus exiting the rotary PX 16. The
first and second fluids 92 and 94 contact one another at an
interface 96 where minimal mixing of the liquids occurs because of
the short duration of contact. The interface 96 is a direct contact
interface because the second fluid 92 directly contacts the first
fluid 94. In some embodiments, there may be a diaphragm or other
barrier at the interface 96 to prevent mixing of the liquids.
[0032] In FIG. 4, the channel 68 has rotated clockwise through an
arc of approximately 90 degrees, and outlet 72 is now blocked off
between apertures 78 and 80 of end plate 64, and outlet 70 of the
channel 68 is located between the apertures 74 and 76 of end plate
62 and, thus, blocked off from hydraulic communication with the
manifold 50 of end structure 46. Thus, the low-pressure second
fluid 92 is contained within the channel 68.
[0033] In FIG. 5, the channel 68 has rotated through approximately
180 degrees of arc from the position shown in FIG. 3. Opening 72 is
in hydraulic communication with aperture 78 in end plate 64 and in
hydraulic communication with manifold 52, and the opening 70 of the
channel 68 is in hydraulic communication with aperture 74 of end
plate 62 and with manifold 50 of end structure 46. The liquid in
channel 68, which was at the pressure of manifold 52 of end
structure 48, transfers this pressure to end structure 46 through
outlet 70 and aperture 74, and comes to the pressure of manifold 50
of end structure 46. Thus, high-pressure first fluid 94 pressurizes
and displaces the second fluid 92.
[0034] In FIG. 6, the channel 68 has rotated through approximately
270 degrees of arc from the position shown in FIG. 4, and the
openings 70 and 72 of channel 68 are between apertures 74 and 76 of
end plate 62, and between apertures 78 and 80 of end plate 64.
Thus, the high-pressure first fluid 94 is contained within the
channel 68. When the channel 68 rotates through approximately 360
degrees of arc from the position shown in FIG. 6, the second fluid
92 displaces the first fluid 94, restarting the cycle.
[0035] FIG. 7 is a more detailed schematic of an embodiment of the
drilling application 2 shown in FIG. 1. As previously discussed,
used drilling mud exits the annulus between the drill string 4 and
the casing 6 and enters the mud cleaning system 12. As shown, the
mud cleaning system 12 may include a shale shaker 150 to separate
cuttings from the used drilling mud. The cuttings may be deposited
in a cuttings pit 152. As illustrated, the used drilling mud is
then processed by a degasser 154, a desander 156, a desilter 158,
and a centrifuge 160 and/or mud cleaner. It should be understood
however, that the mud cleaning system 12 may include any
combination of the previously mentioned components, in any order,
or combinations with additional components. Further, the mud
cleaning system 12 may include one or more intermediate mud pits
162 or tanks to store drilling mud between processes. The drilling
mud may exit the mud cleaning system 12 and be deposited in the mud
pit 14. In some embodiments, the mud loop 30 includes a mixer and a
hopper 164 to keep the drilling mud in the mud pit 14 moving and
mixed up, to add mud to the mud pit 14, to change the composition
of the mud, or to increase flow rates. Though the mixer and hopper
164 in FIG. 7 is shown outside the dotted line that encompasses the
mud cleaning system 12, in some embodiments, the mixer and hopper
164 may be considered a part of the mud cleaning system 12. A
charge pump 166 (e.g., a centrifugal pump) may be used to supply
drilling mud from the mud pit 14 to the LP inlet 24 of the PX
16.
[0036] Meanwhile, a charge pump 168 draws clean water from the
water tank 18 and supplies clean water to the high pressure pump
20. The high pressure pump 20 pressurizes the clean water to
5,000-7,500 psi or more and pumps the water to the HP inlet 22 of
the PX 16. As previously discussed, the PX 16 transfers pressure
from the high pressure clean fluid to the low pressure drilling
mud. High pressure drilling mud exits the PX 16 via the HP outlet
28 and is pumped down the drill string 4. Low pressure clean fluid
exits the PX 16 via the LP outlet 26. Low pressure clean water
exiting the PX 16 may go through a separator 170 to remove
particulates from the clean water. As discussed in more detail
below, in some embodiments (e.g., embodiments with lead flow), the
clean water and the drilling mud may interact with one another
within the PX 16. In such situations, the high pressure drilling
mud may exit the PX 16 via the HP outlet 28 carrying some of the
clean water. Similarly, the clean water may exit the PX 16 via the
LP outlet 26 carrying particulate picked up from the drilling mud
within the PX 16. Accordingly, the separator 170 may be used to
remove the particulate from the clean water. In some embodiments,
the separator 170 may use flocculants or other clumping agents to
separate particulates from the water. As will be discussed in more
detail later, the particulates removed from the clean water may be
discarded or returned to the mud loop 30. In other embodiments, the
clean water loop 32 may include other components for cleaning or
treating the clean water.
[0037] In some embodiments, the flow of clean water between the PX
16 and the water tank may be controlled by controlling the
operation of the PX 16 (e.g., via the charge pump 166). In other
embodiments, the water loop may include a valve 172 (e.g., a flow
control valve) for controlling the flow of clean water between the
PX 16 and the water tank 18. As discussed above, in embodiments of
the drilling application 2 with lead flow, clean water may be mixed
with the drilling mud in the PX 16 and exit the HP outlet 28 with
the drilling mud. Accordingly, in such an embodiment, some clean
water may transition from the clean water loop 32 to the mud loop
30. In such an embodiment, a water makeup flow 174 may add water to
the water tank 18 in order to maintain a relatively constant amount
of water in the clean water loop 32. In some embodiments, the water
makeup flow may also help provide a cooling effect by cooling the
clean water loop.
[0038] In some embodiments, the PX 16 may be driven by a motor 176
(e.g., an electric or gas motor). The motor 176 may or may not be
driven by a variable frequency drive (VFD) 178.
[0039] In some embodiments, the drilling application 2 may include
a controller 180 for controlling operation of the mud loop 30 and
the clean water loop 32. The controller 180 may control the PX 16,
the high pressure pump 20, the charge pumps 166, 168, the valve
172, the motor 176, the VFD 178, any combination thereof, or other
components within the system. For example, the controller may
control flow rates (e.g., via valve position), pump speed, motor
speed, VFD signals, etc. The controller 180 may include a memory
component 182 for storing data and/or programs and a processor 184
for running programs stored on the memory 182. The processor 184
may include one or more general-purpose processors, one or more
application specific integrated circuits, one or more field
programmable gate arrays, or the like. The memory 182 may be any
tangible, non-transitory, computer readable medium that is capable
of storing instructions executable by the processor 184 and/or data
that may be processed by the processor 184. The memory 182 may
include volatile memory, such as random access memory, or
non-volatile memory, such as hard disk drives, read-only memory,
optical disks, flash memory, and the like.
[0040] The controller 180 may act based on inputs received from one
or more sensors 186 disposed throughout the system and configured
to sense flow rates, valve positions, pump speeds, densities, fluid
levels, etc.
[0041] Though not shown, in some embodiments, the drilling
application 2 may include various heat transfer or cooling
components (e.g., heat exchangers, heat sinks, heating components,
cooling components, etc.) to heat or cool mud in the mud loop 30 or
water in the clean water loop 32.
[0042] FIG. 8 is a schematic of an embodiment of the drilling
application in which particulates separated from the clean water by
the separator 170 are added to the mud loop 30 via the mud mixer or
hopper 164 and water removed from the drilling mud by the
centrifuge 160 is sent to the water tank 18. As described above, in
some embodiments, the clean water and drilling mud may interact
with one another in the PX 16. In such cases, the drilling mud may
pick up some of the clean water and/or the clean water may pick up
some particulates from the drilling mud. In such a case, the
separator may be used to separate particulates from the clean water
after the water exits the PX. In some embodiments the particulates
may be discarded. In other embodiments, the particulates may be
added to the drilling mud in the mud pit 14 and travel with the
drilling mud through the mud loop 30.
[0043] Similarly, the centrifuge 160 of the mud cleaning system 12
may be used to separate (e.g., extract) water from the drilling
mud. As shown, the extracted water may be added to the water tank
18. In other embodiments, the extracted water may be discarded.
[0044] FIG. 9 is a schematic illustrating flow rates in an
embodiment of the drilling application 2 with balanced flow. The
flow of the drilling application 2 is balanced when the high
pressure flow rate (i.e., the flow rate into the HP inlet 22 and
out of the HP outlet 28) is substantially the same as the low
pressure flow rate (i.e., the flow rate into the LP inlet 24 and
out of the LP outlet 26). For example, the high pressure flow rate
may be within 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%,
13%, 14%, 15%, or some other value, or the low pressure flow rate.
As shown, the flow rates Q in each portion of the mud loop 30 and
the clean water loop 32 are expressed as a percentage of the flow
rate of drilling mud out of the HP outlet 28 of the PX 16 and to
the drill string 4. As shown, the flow rate Q of the used drilling
mud out of the casing 6 is 100, plus cuttings and minus any fluid
losses. As the drilling mud goes through the mud cleaning system
12, the flow rate Q decreases. For example, drilling mud may exit
the mud cleaning system 12 with a flow rate Q of 80, 85, 90, 95, or
some other value. The mud mixer and hopper 164 may be used to
increase the flow rate Q by 5%, 10%, 15%, 20%, or some other value
such that drilling mud enters the PX 16 at the LP inlet 24 at a
flow rate Q of 100.
[0045] Similarly, water may be pumped from the water tank and into
the HP inlet 22 of the PX 16 at a flow rate Q of 105, assuming
approximately 5% leakage or lubrication flow (e.g., fluid which
migrates from the HP flow to the LP flow within the PX 16). Water
exits the PX 16 at a flow rate Q of 105, goes through the
separator, and is deposited in the water tank 18. In the balanced
flow embodiment illustrated in FIG. 9, the flow rate Q of the water
makeup flow 174 may be small, or in some cases, even zero. For
example, the flow rate Q of the water makeup flow 174 may be 0, 1,
2, 3, 4, 5, 6, 7, 8, 9, 10, or some other value. In some
embodiments, the water makeup flow 174 may be used to account for
water lost to leakage.
[0046] FIG. 10 is a schematic illustrating flow rates in an
embodiment of the drilling application 2 with 20% lead flow (e.g.,
the HP flow rate is greater than the LP flow rate). As shown, the
flow rate of the used drilling mud out of the casing 6 is 100, plus
cuttings and minus any fluid losses. As the drilling mud goes
through the mud cleaning system 12, the flow rate Q decreases. For
example, drilling mud may exit the mud cleaning system 12 with a
flow rate Q of 80, 85, 90, 95, or some other value. In the lead
flow example, the mud mixer and hopper 164 are not used to increase
the flow rate Q, such that drilling mud enters the PX 16 at the LP
inlet 24 at a flow rate Q of less than 100. For example, drilling
mud may enter the LP inlet 24 of the PX 16 at a flow rate Q of 70,
75, 80, 85, 90, or some other value. As the drilling mud travels
through the PX, the drilling mud may take on some of the clean
water such that the drilling mud exits the HP outlet 28 of the PX
16 at a flow rate Q of 100.
[0047] Similarly, water may be pumped from the water tank and into
the HP inlet 22 of the PX 16 at a flow rate Q of 105, assuming
approximately 5% leakage. Because the drilling mud takes on some of
the clean water as it travels through the PX 16, water exits the LP
outlet 26 of the PX 16 at a lower flow rate Q (e.g., 70, 75, 80,
85, 90, or some other value), goes through the separator, and is
deposited in the water tank 18. Water may be added to the water
tank 18 via the water makeup flow 174 to account for water taken on
by the drilling mud in the PX 16. For example, the flow rate Q of
the water makeup flow 174 may be 10, 15, 20, 25, 30, or some other
value. The water makeup flow 174 may also be used to account for
water that leaks to the drilling mud in the PX 16. In some
embodiments, the water makeup flow 174 may also be used to cool the
clean water loop.
[0048] FIG. 11 is a flow chart of a process for pressurizing
drilling mud. In block 202, used drilling mud is received from the
well (e.g., from the annulus between the drill string and the
casing). In block 204, the used drilling mud may be cleaned. As
described above, this may include shale shaking to separate the
drilling mud from the cuttings, degassing, desanding, desilting,
and running through a centrifuge to separate various components of
the drilling mud. Once cleaned, the drilling mud may be deposited
in a mud pit. In block 206, low pressure drilling mud is provided
to the LP inlet of the PX. In block 208, the clean fluid (e.g.,
clean water) is pressurized using a pump and provided to the HP
inlet of the PX. In block 210, the pressures are exchanged between
the high pressure clean fluid and the low pressure drilling mud.
Thus, the low pressure drilling mud is pressurized and the high
pressure clean fluid is depressurized. The high pressure drilling
mud exits the PX via the HP outlet. The low pressure clean fluid
exits the PX via the low pressure outlet. In block 212, the low
pressure clean fluid is deposited in the water tank or other
containment device. In some embodiments (e.g., lead flow) a water
make up flow may supply supplemental water to the water tank in
order to make up for water lost to leakage or taken on by the
drilling mud in the PX. In block 214 the pressurized drilling mud
is provided to the cutting head via the drill string. The drilling
mud provides hydraulic power, cooling, well control (e.g., using
the weight and pressure of the mud to control the well, which may
encounter pressurized fluids in the formation), and also carries
cuttings away from the cutting head as the drilling mud is pumped
back up to the surface in the annulus between the casing and the
drill string.
[0049] Using one or more PXs to transfer pressure from a clean
fluid to drilling mud for mud pumping in a drilling application
means that the high pressure pump pumps clean fluid, rather than
drilling mud. Thus, the high pressure pump does not have to
withstand the stress caused by cuttings, clay, various minerals,
aggressive chemicals, salts, and miscellaneous other components in
the drilling mud. The disclosed techniques may result in increased
lifespan and increased efficiency of the high pressure pump
relative to typical systems in which the high pressure pump pumps
drilling mud. Additionally, in some configurations, because the
pump is pumping clean fluid instead of drilling mud, a higher
performance or more efficient pump may be chosen because durability
is not as much of a concern. Similarly, because the pump is not
pumping drilling mud, in some instances the mud cleaning process
may be less thorough, thus potentially saving time and money.
[0050] While the disclosed subject matter may be susceptible to
various modifications and alternative forms, specific embodiments
have been shown by way of example in the drawings and have been
described in detail herein. However, it should be understood that
the disclosed subject matter is not intended to be limited to the
particular forms disclosed. Rather, the disclosure is to cover all
modifications, equivalents, and alternatives falling within the
spirit and scope of the disclosure as defined by the following
appended claims.
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